By: Arash Dara, Middle East Lead, Accenture Trading Investments Optimization Strategy (ATIOS) Group
The oil market will continue to be an uncertain and increasingly challenging environment for both corporate and government players to navigate. Whilst China imported 8.55 million barrels per day in the first half 2017, up 13.8 per cent from the same period in 2016, making it the world’s biggest crude importer (EIA STEO Repot), and despite the extension of the production cuts agreement by OPEC and non-OPEC exporters in a bid to boost the price, the market is having difficultly picking up.
According to the IEA, the market could stay oversupplied for longer than expected due to rising production and limited output cuts by some OPEC members, notably Libya and Nigeria, who were exempt from the production cuts.
Compounded with resurgent US shale operations, the global fuel glut is taking longer than anticipated for exporters. Oil inventories in industrialised nations remain substantial. OECD stocks are 170 million barrels above the five-year average. Analyst expectations believe the price environment will not significantly improve, continuing to apply pressure and squeeze margins on many upstream focused NOCs.
The macro-environment is out of their hands, but what they can control is their operations. As stewards of national resources, NOCs need to harness the maximum potential of the hydrocarbons they have access to. At the same time, they must look beyond those resources to remain competitive, improve margins and reduce costs. To succeed in this new world of lower for longer, NOCs will need to be both agile and adaptable, connected and collaborative. This means reshaping their companies across four dimensions:
NOCs need to utilise enhanced digital technologies to help them manage through the low oil price environment. An example of this is advanced analytics, which are enabling upstream oil and gas companies to reduce costs, better manage operations and mitigate risks. In a recent Accenture O&G survey, Analytics was identified as one of the largest opportunity areas where digital can help transform oil and gas companies, yet most respondents felt their company did not have sufficiently mature analytics capabilities to realise the full value.
International assets, if any, to pursue
NOCs could also look to international assets for economic reasons, that is, if the NOC has an undisputed production advantage that makes the return on international assets exceed whatever handicap the NOC faces at home. If NOCs have the liquidity and foresight, the purchase of international assets that others may be looking to sell as noncore properties to generate cash, or the acquisition of distressed competitors that have strategic value, could pay off in the long run in this buyers’ market.
Saudi Aramco has been diversifying their portfolio for years and continue to do in the lower oil price environment. Aramco recently invested US$7 billion into a Petronas oil refinery and petrochemical project in Malaysia’s southern state of Johor, and has signed US$50 billion worth of deals with U.S. companies during U.S. President Donald Trump’s visit to Saudi Arabia.
Diversification from upstream further into the oil and gas value chain
NOCs have a far greater exposure to the upstream business than IOCs, which leaves them more vulnerable during commodity price down cycles. In the latest downturn, refining and midstream businesses posted healthy margins. Most NOCs currently don’t take advantage of this opportunity as much as the majors. A balanced portfolio provides stability and helps mitigate risk in a volatile price environment.
Abu Dhabi is balancing growth and cashflow. It is more than tripling its domestic petrochemical output by 2025 and ADNOC have recently been turning their attention to the issue, stating better infrastructure requirements to link producer to end user. They’ve also signed an exclusive agreement with Penthol, a global organisation in the supply and distribution of oil products and petrochemicals, to be the exclusive seller of ADNOC’s Group III base oil in US.
Potential participation in the new energy system
With alternative energy types and business models poised to assume a greater role in the overall energy sector, NOCs will need to at least consider the question of whether they should play beyond hydrocarbons. The shift may also be driven by national policies focused on reducing the host country’s carbon emissions, but a move from black to green will also offer opportunities to build on a growing market, and provide a long-term buffer for the slowing demand for oil.
Saudi Aramco is also making great strides in this area, currently mulling roughly $5 billion in renewable energy investments and has recently signed partnerships with ADNOC and Masdar to collaborate on sustainable development and renewable energy to yield advancements in clean electricity generation and carbon management. Some NOCs may feel powerless to the price of oil and its impact on profitably, but they have an opportunity to take control of their operations, and push through innovative technologies and processes, increasing profit margins in this uncertain environment and positioning them at ever greater advantages for upturns.
By: Mustafa Ansari, analyst, energy research at APICORP
An economic slowdown coupled with energy reforms has adversely affected domestic fuel consumption growth across most of the GCC, and in some cases even led to negative growth. While a similar trend could be observed in most countries in the region, it was especially pronounced in Saudi Arabia. The region’s largest fuel consumer saw a 10 per cent decrease in demand for diesel in 2016, while gasoline demand flat lined. The UAE is the only GCC country where demand for both gasoline and diesel increased in the same period in the wake of the energy liberalisation plans implemented in August 2015.
Ever since January 2015, oil prices have teetered around the US$50 mark, placing huge fiscal pressures on net oil-exporting countries. Declining GDP growth rates and reduced government revenues led many countries in the region to initiate energy reforms and cut subsidies. While the new prices were still low by international standards, the reforms represented a fundamental shift in economic and social policies. The resulting effects of higher domestic energy prices and lower economic growth have in turn driven domestic demand for petroleum products down.
This development means that net energy exporters have benefitted from higher export volumes than they would have otherwise, slightly offsetting the lower revenues.
But oil prices have failed to recover, despite a collective agreement from OPEC in November 2016 to cut output. In the 16 years since the turn of the century, the MENA region added more than 4.8 million barrels per day (bpd) to global oil demand, second only to China’s 7.9m bpd and ahead of Africa, Latin America and the rest of Asia (excluding China). But demand will likely slow down further as countries in the region continue to undergo energy reforms.
Slowing GCC demand sends mixed signals
Rapidly growing demand for petroleum products has long been typical for the GCC countries. High population growth, robust economic performance until recently, and low fuel prices led to rising demand for gasoline and diesel in the transportation sector, and in the case of Saudi Arabia and Kuwait, rising demand for liquids in the power sector.
Governments therefore prioritised the expansion of the downstream sector, adding 1.2 million bpd of refining capacity in the last five years, with diesel representing more than half the additions and 350,000 bpd of gasoline. In early 2016, the GCC introduced energy price reforms that led to a hike in domestic prices, including gasoline and diesel. Whilst prices remained relatively low by global standards, the region began to experience a slowdown in demand growth and in some cases negative growth.
Annual gasoline demand growth averaged 6.2 per cent between 2010 and 2015 but shrunk to 0.4 per cent in 2016. The change in diesel demand was even more significant, going from an average of 4 per cent growth between 2010 and 2015 to a 6 per cent decline in 2016. Beyond the impact of the reform, the slowdown in economic activity also contributed to lower demand growth, and as these economies recover, some of this demand growth will gradually return.
UAE demand least affected
Despite its strong fiscal position, the UAE was one of the first countries in the GCC to liberalise its gasoline and diesel prices back in August 2015. The government still sets the domestic fuel prices on a monthly basis, but these are directly linked to international prices. The UAE has introduced electricity reforms, but the impact on the country’s nationals has been limited (especially in Abu Dhabi) with non-UAE nationals bearing the brunt of the reform. Subsidies for natural gas, which account for the bulk of the UAE’s subsidies, remain in place.
Amongst its GCC peers, the UAE was the only country where demand for both gasoline and diesel increased in 2016 compared with the year before (plus 20 per cent and 40 per cent, respectively). The trend in gasoline demand since 2010 has been upwards, having increased each year with the exception of 2014 when it slipped from 70,000 bpd to 63,000 bpd. Meanwhile, demand for diesel had been shrinking marginally from 85,000 bpd in 2010 to 71,000 bpd in 2015. But a significant increase to 99,000 bpd could be observed in
2016, when domestic retail prices dropped further in line with international prices. Liberalising prices in the UAE has received wide media attention. With the continued slump in oil prices, the initial impact on gasoline was negligible as prices were already close to international levels. But gasoline prices soon went from an average of $0.48 in 2015 to as low as $0.36 in March 2016, as international prices dipped below $30 per barrel in the beginning of 2016. For diesel, however, the situation is different: a prolonged trend of price cuts continued into 2016, with prices dropping to their lowest level in July. This contributed to an increase in demand for both products. Average demand for gasoline in 2015 jumped up from 69,000 bpd in the first half of the year to 108,000 bpd in the second half. Similarly, average demand for diesel increased from 69,000 bpd to 74,000 bpd over the same timeline. Although prices have fluctuated this year, they have remained on a relatively low level. Notably, there did not seem to be a correlation between monthly prices and demand, but an upside trend in demand could be noticed throughout the year.
VAT set to exert downward pressure on demand
Energy consumption is certainly important for growth. For decades, the provision of cheap energy has been a main pillar of GCC development strategy aimed at achieving key economic, social and political objectives. Low energy prices have enabled the GCC to achieve some of these objectives. Earlier in the year, the UAE announced that a 5 per cent value added tax (VAT) will be implemented from January 2018 as part of their efforts to diversify revenues. Whilst the tax will be exempt on products such as social services, health and education, it will be imposed on general household goods including electronics, entertainment, new vehicles and transportation fuel. In most countries, businesses can claim back VAT on commercial vehicles, but at this stage the rate in the UAE for both individual and commercial vehicles will be the same.
Although the tax is low by international standards, it will nevertheless increase domestic prices and will likely place downward pressure on demand. Certainly, for the oil industry, a slowdown in fuel consumption may lead to lower output levels, lower utilisation rates, lower demand for skilled labour and higher costs. Rapid demand growth in the past meant that the level of investment required to keep pace became unsustainable. But on the upside, lower consumption will free up more products for exports. In 2014 the UAE added 417,000 bpd of refining capacity with the start-up of Ruwais where it substantially affected trade balances, turning the country into a net exporter of both gasoline and fuel oil and substantially raising diesel exports.
With the ramp-up of the Ruwais refinery in 2015 and an additional 70,000 bpd of refining capacity expected in the next five years from the Jebel Ali condensate splitter expansion, the UAE could further benefit from higher export revenues.
What’s next for the GCC?
In its July update, the IMF predicted a considerable slowdown in growth, especially if oil prices remain low. MENA GDP growth is expected to average 2.7 per cent this year and to recover modestly to 3.3 per cent by 2020. Oil prices might remain lower over the long term, meaning that further policy reforms will be necessary to alleviate fiscal pressures. But there is a bright spot amidst the gloom. Energy consumption growth is clearly slowing down in most countries in response to energy subsidy cuts, which will help regional governments save millions whilst also freeing up more products for exports.
The UAE are well placed to take the lead in this new opportunity. Rapid demand growth in the past meant that the level of investment required to keep pace became unsustainable. Lower domestic demand levels will ensure that the region can maintain its position as a leading energy exporter, whilst simultaneously working towards economic diversification to reduce dependence on export revenues. In the absence of economic recovery, demand growth for transportation fuel products could decline further.
Whilst gasoline demand has not dropped significantly, not least due to fuel switching from premium to regular grades, governments need to invest more in public transport to reduce reliance on transportation fuel. Still, with a global oversupply of products, the GCC countries are challenged to ensure that they remain competitive. But, as the regional economies enter the recovery phase, we are set to see some of this demand growth gradually return.
Digital technologies are set to transform the global energy system in coming decades, making it more connected, reliable and sustainable. This will have a profound and lasting impact on both energy demand and supply, according to a new report by the International Energy Agency, Digitalization & Energy.
In this first comprehensive report on the interplay between digitalisation and energy, the IEA analyses how digitalisation is transforming energy systems. From the rise of connected devices at home, to automated industrial production processes and smart mobility, digital technologies are increasingly changing how, where and when energy is consumed.
More than 1 billion households and 11 billion smart appliances could participate in interconnected electricity systems by 2040, thanks to smart meters and connected devices, the report said. This would allow homes to alter when and how much they draw electricity from the grid. Demand-side responses - in building, industry and transport - could provide 185 GW of flexibility, and avoid US$ 270 billion of investment in new electricity infrastructure.
With the help of smart thermostats, the IEA report finds that smart lighting and other digital tools, buildings could reduce their energy use by 10 per cent by using real-time data to improve operational efficiency. Meanwhile, massive amounts of data, ubiquitous connectivity, and rapid progress in Artificial Intelligence and machine learning are enabling new applications and business models across the energy system, from autonomous cars and shared mobility to 3D printing and connected appliances.
The same transformation is taking place in how energy is produced - from smart oil fields to interconnected grids, and increasingly, renewable power. Digital technologies could help integrate higher shares of variable renewables into the grid by better matching energy demand to solar and wind supplies. Energy supply sectors also stand to gain from greater productivity and efficiency, as well as improved safety for workers.
"Digitalisation is blurring the lines between supply and demand," said IEA executive director Dr Fatih Birol. "The electricity sector and smart grids are at the centre of this transformation, but ultimately all sectors across both energy supply and demand - households, transport and industry - will be affected."
In parallel with these opportunities, digitalisation is raising new security and privacy risks, as well as disrupting markets, businesses and employment. While the growth of the "Internet of Things" could herald significant benefits in terms of energy efficiency to households and industries, it also increases the range of energy targets for cyber-attacks. Such attacks have had limited impact so far, but they are also becoming cheaper and easier to organise.
To help understand and deal with this fast-evolving landscape, the report concludes with 10 no-regret policy recommendations, as sound policy and market design will be critical in steering a digitally enhanced energy system along a more efficient, secure, accessible and sustainable path.
Energy suppliers will reap greater productivity and improve safety
Digitalisation can improve safety, increase productivity and reduce costs in oil and gas, coal and power. The magnitude of these potential impacts – and associated barriers – varies greatly depending on the particular application, the report said.
Oil and gas
The oil and gas sector has a relatively long history with digital technologies, notably in upstream, and significant potential remains for digitalisation to enhance operations. Further digitalisation in the upstream oil and gas industry in the future is likely to initially focus on expanding and refining the range of existing digital applications already in use, IEA said in its report.
For example, miniaturised sensors and fibre optic sensors in the production system could be used to boost production or increase the overall recovery of oil and gas from a reservoir. Other examples are the use of automated drilling rigs and robots to inspect and repair subsea infrastructure and to monitor transmission pipelines and tanks. Drones could also be used to inspect pipelines (which are often spread over extended areas) and hard-to-reach equipment such as flare stacks and remote, unmanned offshore facilities.
In the longer term, the potential exists to improve the analysis and processing speed of data, such as the large, unstructured datasets generated by seismic studies. The oil and gas industry will furthermore see more wearables, robotics, and the application of artificial intelligence in their operations.
Widespread use of digital technologies could decrease production costs between 10 per cent and 20 per cent, including through advanced processing of seismic data, the use of sensors, and enhanced reservoir modelling. Technically recoverable oil and gas resources could be boosted by around 5 per cent globally, with the greatest gains expected in shale gas.
Wood Mackenzie: Libya hits production landmark but political divisions overshadow outlook
In August 2016, blockades of key export terminals and pipelines saw production fall below 300,000 barrels per day (bpd). Output has since rebounded. Credit is due to NOC and its indefatigable boss, Mustafa Sanalla. The company has been integral to the country’s production recovery, resisting demands by militia and tribes and methodically calling out how much "spoilers" have cost the country. Campaigns to keep oil flowing have reduced and shortened the length of disruptions, and attempts by the eastern House of Representatives (HOR) administration to market crude independently have receded. NOC remains one of the last functioning institutions of the state, able to act independently of Libya's competing administrations with the goal of depoliticising oil restoring output.
Other events, including repairs to infrastructure damaged by insurgents, field restarts and blockades on major pipelines being lifted, all contributed to growing production.
But doubts remain that these increases can be sustained. Fighting and blockades continue to cause output to fluctuate, and Libya's myriad of tribes and militias continue to target infrastructure as a means to leverage their demands. NOC previously announced that it had hoped to reach 1.25 million bpd by the end of this year, ramping up to 1.5 million bpd by the end of 2018. This now looks ambitious, even by NOC's own admission.
In the near term, we consider that Libya may now be approaching its production limits. There are a number of reasons for this. Export ports are key to incremental growth. Crucially, capacity at As Sidrah, the country’s largest port, was reduced by rocket attacks in 2016. Reinstating Sidrah's capacity to its pre-war level of 450,000 bpd will take several years. It is uncertain how much of this capacity has been destroyed, but we estimate it to be operating at less than 100,000 bpd. Effective export capacity is thus estimated to be restricted to around 1.25 million bpd.
Realising available capacity will require remedial efforts upstream. Near- to medium-term incremental gains will be more modest, as the easiest gains have been made. In the east, in particular, greater investment will be required to address years of under-investment in ageing facilities and leaky pipelines.
Looting and sabotage have also taken a toll: up to 100,000 bpd of production is understood to have been lost due to attacks on facilities. Many of these projects, including Mabruk and Ghani, will require complete rebuilds. This will not occur until the security and the investment climate has improved markedly.
IOCs will be reluctant to return capital so long as insecurity and competing administrations persist.
Accessing equipment, already harder with port closures, and undertaking basic maintenance compound the challenge. The exodus of service companies and hefty risk premiums will drive up costs significantly, once companies judge the environment safe enough to resume operations.
The most readily accessible upside barrels may be in the west where El Sharara and Elephant (El Feel) could perhaps yield an additional 100,000 bpd with some investment. Infrastructure in the west is also newer and has not been subject to sabotage.
We do not see Libyan production returning to pre-war levels until well into next decade and think that, without IOC involvement, maintaining and realising modest gains on a baseline of 1 million bpd could be considered a success in itself.
Conversely, greater downside exists. Production remains highly susceptible to disruptions. A deteriorating political situation or further shut-ins of key infrastructure could limit production to offshore fields and NOC fields in the east which have remained consistent throughout.
For investors seeking steady barrels and predictable cash flows, Libya has long since lost its lustre. North American companies have demonstrated less risk tolerance than their peers. We consider further divestments from companies holding mature, non-core positions plausible. European incumbents and Asian NOCs looking for long-term barrels are the likely buyers, but would-be sellers may wait for greater stability to capture price upside, rather than selling at a discount.
For others, Libya still holds appeal. Billion-barrel brownfield developments, lifting costs below $5 per barrel and proximity to European markets make the conflict worth sitting out. European IOCs have come to view the risks as manageable; whilst a reticence to invest will continue, some are beginning to return gradually. Volumes present a large upside and, when oil flows, cash flow is good. Prolonged stability could yet see operators in the west, where an outlet for production upside exists, and recommence development drilling in 2018.
The return of Libyan oil to the market has come as other OPEC and non-OPEC parties have agreed to extend production cuts in a bid to boost oil prices. Libya was exempt from recent OPEC accords as it struggled to rebuild production lost due to internal fighting and instability. How long OPEC continues to exempt Libya from quotas will ultimately depend on how the political situation unfolds.
While gas markets are currently well supplied, the transformation of natural gas markets from regional systems to more globalised and interdependent markets is creating new security challenges, according to the International Energy Agency's latest assessment of global gas security.
The IEA's second Global Gas Security Review looked at recent gas balancing issues and risks with related policy developments linked to security of supply - including the stressed situations in natural gas and power markets experienced by several southern Europe countries in the winter of 2016-2017; the diplomatic tensions in the Gulf; and the supply risks posed by recent hurricanes on the United States energy system.
The report details how importing countries in mature and well-interconnected markets can still experience unexpected shocks that put strong pressure on the market. Even in the current low-price environment, suppliers are still exposed to low-probability but high-impact events that could have potentially serious consequences for global gas supplies.
"As recent events demonstrated, the security of natural gas supplies cannot be taken for granted even with the current low price environment and oversupplied market," said Dr Fatih Birol, the IEA's executive director. "From cold spells in southern Europe, to hurricanes in the Gulf of Mexico, to diplomatic tensions among Gulf countries, energy security is impossible to ignore."
This year's edition updates these metrics and shows a continuing improvement in supply availability and contractual flexibility, which are expected to grow in the near future, along with diversification of market participants.
LNG contract flexibility appears as an important determinant of the resiliency of the global gas system. The report's updated analysis of new signed contracts shows clear evidence of contractual structures becoming less rigid, a trend evidenced by the growing share of flexible destination contracts, as well as the decrease in contracts' average duration.
The report also looks at how contract flexibility will develop over the next five years. Looking forward, the pool of legacy export contracts with fixed destination and long duration can be expected to shrink as these expire, and be replaced by more flexible contracts. The development of US exports emerges as a major source of additional contractual flexibility. Global portfolio players would play an increasing role and provide additional flexibility from their currently open selling positions.
To improve the risk assessment of importing countries, the report also introduces a new typology of LNG buyers as a tool to measure market exposure, and related security of supply issues. This typology also suggests a way to measure future LNG market evolution.
Converging oil price expectations of investors and companies in the oil and gas sector creates a strong platform for M&A deals to flourish, according to A.T. Kearney’s 2017 Oil and Gas M&A study. The report reveals a sharp pick-up in deals announced at the end of last year, although 45 percent of the US$850 billion worth of transactions declared since January 2016 is still pending.
“The oil and gas industry has a tremendous opportunity to benefit from stabilising oil prices that can fuel deal activity in order to improve balance sheets, and raise cash for capital projects through divestitures,” said Brent Ross, principal, A.T. Kearney and co-author of the study. “In addition, many buyers need acquisitions to replenish reserves that dwindled during the challenging environment of the past two years.”
The study identified strong optimism for the year ahead, with more than two-thirds of the executives surveyed expecting M&A to rise moderately or even aggressively in the year ahead.
“In the Middle East, we expect to see an increase in M&A and partnerships in the Oil & Gas industry. National oil companies in the Gulf will continue to seek access to the key technologies and capabilities that they need to expand their domestic business and to create more value. In parallel, they will continue to explore partnership opportunities to secure access for their crude and fuel products in international markets, while capturing a larger share of the profit pool,” said Ada Perniceni, partner, A.T. Kearney and co-author of the study.
Across the world, improved market conditions have sparked several megadeals since 2016, including Sunoco’s $50 billion purchase of Energy Transfer Partners, the US$43 billion merger of Enbridge and Spectra Energy, and a $32 billion deal that combined GE’s oil and gas operation with Baker Hughes.
With signs that investment prospects are improving, the study indicates that financial investors will be more active in 2017 and are open to new deal structures. With oil prices holding steady and industry sentiment improving, investors are moving to capture acreage, secure midstream assets with reliable returns, and capitalize on opportunities in oil services.
“Long-term uncertainty as a result of energy transition, concerns of peak oil demand, and digital trends, means companies are also pursuing strategic transactions in alternative energy and new capabilities centred around digitalization to be better placed in a changing energy value chain,” said Richard Forrest, A.T. Kearney global lead partner for the Energy Practice and co-author of the study.
The fog is lifting on the oil and gas M&A landscape, but the horizon remains hazy. Companies need to retain a strong focus on cost control and leverage digitalization to improve the efficiency and effectiveness of operations and capital deployment. They will also need to prepare an uncertain future with a shift of strategies to reflect accelerating energy transition and the impact of new disruptive technologies. Mergers and acquisitions will be an important lever for oil and gas companies, both in the short and long term, to remain successful.
A new report by Wood Mackenzie, Non-OPEC Decline Rates: Lower for Longer, looks at the factors influencing this stability, how long it can be maintained and the impact future shifting decline rates may have on the oil market.
Through operational excellence programmes and smart spending, operators have managed to maximise production and improve efficiencies, bucking expectations of an increase in decline rates. In fact, non-OPEC decline rates have remained stable since 2015.
Dr Patrick Gibson, research director, Global Oil Supply, at Wood Mackenzie, said: “Decline rates are a critical factor influencing the current rebalancing of the oil market and price recovery. A 50 per cent cut in investment in non-OPEC producing oilfields and a dwindling pipeline of new projects since the price crash should have led to progressively steeper decline rates. Nonetheless, decline rates have held steady at around 5 per cent since 2015 and we expect they will remain at this level until 2020.”
Wood Mackenzie's analysis shows that, annual decline rates for conventional fields peaked at nearly 7 per cent during the last decade, or 2.4 million bpd a year. However in 2014, they reached an historical low of just 3.6 per cent, or 1.2 million bpd. The price collapse saw decline rates increase to 5.1 per cent, or 1.9 million bpd in 2015, on the back of steep spending cuts. Decline rates have stayed at around that level since.
"Stable rates of non-OPEC decline is a disappointing story for those looking for significant price support coming from declining conventional production," Dr Gibson said.
He said improved operating efficiency and focused capital expenditure (capex) have helped maintain decline rates at current levels. Operators have maximised production rates by focusing on the best-performing wells, as well as targeting processes and maintenance programmes so uptime is increased.
"Careful budgeting is also in play," Dr Gibson added. "Slashed capex now predominantly targets short-cycle opportunities with high returns potential, while development plans and service-sector cost cuts have bolstered spending efficiency."
While some shorter-term measures may relax, longer-term factors, such as increased production from 'zero decline' assets and early-life assets, will help keep decline rates steady. Wood Mackenzie's analysis shows early-life assets increasing their proportion of production from 6 per cent in 2010 to 30 per cent by 2020. The lower decline rates of these assets counter-acts the higher declines of more mature assets.
Dr Gibson said: "Canada's oil sands and Brazil's deepwater pre-salt play are adding a growing proportion of production, significant enough to offset global decline rates. The oil sands alone could reduce decline rates by as much as 0.6 per cent in 2020."
Technology will also play a role in maintaining stable decline rates, as evidenced by developments in horizontal drilling, hydraulic fracturing, enhanced oil recovery techniques and CO2 flooding in the US, Canada, and Russia.
Beyond 2020, Wood Mackenzie expects decline rates will return to the historical norm of around 6 per cent, and higher oil prices will be needed to incentivise investment in new production to meet a widening supply gap. Even moderate swings in average annual decline rates are capable of influencing the market; the rate of decline for non-OPEC fields is crucial to the global supply picture. A 1 per cent shift in annual global decline rates would have a significant effect on supply, potentially adding or removing 2 million bpd by 2021.
"Our current modelling shows stable decline rates until 2020, then a widening to 6 per cent in 2021. Although the present picture is one of resilience and smart spending, further gains remain unlikely. With investment so low, the industry is potentially storing up problems for supply that won't become apparent until after the end of the decade."
Gas will become the single biggest source of energy by 2050 even as rapid decarbonisation gives rise to renewables – DNV GL said in its inaugural Energy Transition Outlook.
“The world is approaching a watershed moment as energy demand is set to plateau from 2030, driven by greater efficiency with the wider application of electricity,” DNV said in a report that charts the world’s energy future.
“As a company, we are highly exposed to the radical changes that will come to every part of the energy value chain, and it is critical for our customers and ourselves that we understand the nature and pace of these changes,” said Remi Eriksen, group president and CEO of DNV GL.
“The profound change set out in our report has significant implications for both established and new energy companies. Ultimately, it will be a willingness to innovate and a capability to move at speed that will determine who is able to remain competitive in this dramatically altered energy landscape.”
DNV GL, a quality assurance and risk management company providing independent advisory services to the oil & gas industry, said that historically, energy demand and CO2 emissions have moved broadly in line with GDP and population growth, but that relationship will unravel.
Electrification, particularly with the uptake of renewables, will change the way in which energy is supplied and consumed. While the global economy and world population are set to grow modestly, energy demand will flatten out and CO2 emissions will drop sharply, according to the report.
DNV GL forecasts that renewables and fossil fuels will have an almost equal share of the energy mix by 2050. Wind power and solar photovoltaics (PV) will drive the continued expansion of renewable energy, whilst gas is on course to surpass oil in 2034 as the single biggest energy source. Oil is losing ground as a source of heat and power, and is set to flatten from 2020 through to 2028 and fall significantly from that point as the penetration of electric vehicles gains momentum. Coal use has already peaked.
The global energy transition will occur without a significant increase in overall annual energy expenditure and on a straight comparison, the world’s energy will cost less than 3 per cent of global GDP compared to the current level of 5 per cent, the report said.
Although the oil and gas industry has responded impressively to the present lower price environment, renewables will improve cost performance at a much faster rate, benefitting from the ‘learning curve’ effect. Electric vehicles will achieve cost parity with internal combustion vehicles in 2022 and, by 2033, half of new light vehicle sales globally will be electric.
Despite greater efficiency and reduced reliance on fossil fuels, the Energy Transition Outlook indicates that the planet is set to warm by 2.5˚C, failing to achieve the 2015 Paris Agreement target.
“Even with energy demand flattening and emissions halving, our model still points to a significant overshoot of the 2°C carbon budget. This should be a wake-up call to governments and decision-makers within the energy industry. The industry has taken bold steps before, but now needs to take even bigger strides,” said Eriksen.
The International Maritime Organization (IMO) recently confirmed that global refiners and shippers must comply with new regulations to reduce the sulfur content in marine bunker fuels by January 2020—five years earlier than many expected. As a result, both the global refining and shipping industries will experience rapid change and significant cost and operational impacts, according to new analysis from IHS Markit.
“While the IMO is taking positive action to address the environmental impacts of air pollution from ships, the rapid change creates significant disruption for both the refining and shipping industries,” said Kurt Barrow, vice president of downstream research at IHS Markit. Barrow, along with Sandeep Sayal, senior director of refining and marketing research at IHS Markit, are two authors of an IHS Markit report entitled Refining and Shipping Industries Will Scramble to Meet the 2020 IMO Bunker Fuel Rules.
“The two industries are vastly unprepared,” Sayal said. “Neither has made the necessary investments for compliance, which means that the 2020 implementation date will result in a scramble. Both industries are taking a wait-and-see approach until firm signals are in place by the IMO for compliance with the regulation."
“Shippers will face significant compliance costs by having to upgrade equipment or switch to more expensive fuels,” Barrow said. “Refiners will experience significant price impacts as they shift production to deliver more lower-sulfur fuels to the market and, at the same time, find a market for the higher-sulfur fuels they produce. Refineries, like ships, do not turn on a dime, so it takes significant investment and market demand to retool a refinery to deliver new supply.”
Shippers will have several options to meet the new IMO regulations, IHS Markit said. Low-sulfur bunker fuels (primarily for smaller vessels), and liquefied natural gas (LNG) (primarily for new builds) will be part of the solution. However, IHS Markit researchers expect that on-board ship scrubbers, devices that clear harmful pollutants from exhaust gas, will be the primary compliance path for ships, which could continue to burn higher-sulfur fuels.
“From the shipping industry point of view, IHS Markit estimates that about 20,000 ships account for around 80 percent of heavy fuel-oil bunker fuel use,” said Krispen Atkinson, senior consultant, IHS Markit Maritime & Trade research. “Currently only about 360 ships have installed scrubbers, since there is currently no economic incentive for the ships to add scrubbers. However, based on the price spreads between low-sulfur bunker fuel and high-sulfur fuel oil during the scramble period, it will be economic for many of them to install scrubbers.” The payback period for installing a scrubber on the largest vessels, Atkinson said, would be two-to-four years in 2022-2025, and less than one year based on peak-price spreads in 2020.
A key uncertainty also lies in the actual level of compliance to the IMO regulation in 2020. “Not only is it hard to enforce compliance in the open seas, but it is still uncertain if sufficient supplies of compliant bunker fuels will be broadly available in all ports,” Sayal said.
Overall, the installations of scrubbers and some level of noncompliance will not be in time to halt the disruption on refined products markets, IHS Markit said. According to the IHS Markit report, the primary challenge with the bunker fuel quality change (which requires sulfur content to be reduced from 3.50 percent by weight to 0.5 percent by weight) is the disposal of high-sulfur residual fuel—not the production of low-sulfur bunker fuel.
“When we account for all the supply and demand factors for the sour residual balance, including new conversion projects, capacity creep, scrubber and LNG capacity, as well as quality compliance, our bottom line is that a sizable portion of today’s fuel oil will be pushed into lower-price tiers, notably oil-fired power-generation plants,” Barrow said. “Refining capacity will most likely exist in 2020 to produce the low-sulfur bunker fuel, but higher overall crude runs will be required.”
The largest refinery margin disruption will be significant but fleeting, according to the IHS Markit report, with impacts felt most notably in 2020 and 2021. IHS Markit expects an unprecedented light-heavy price spread during 2020 to 2021. During these years, pricing for high-sulfur fuel oil (HSFO) will have to be near thermal parity with coal to clear into the power market—a very low price relative even to today’s fuel oil price, IHS Markit said.
As ship owners respond to the large-scrubber investment incentives, high-sulfur bunker fuel demand will rebound, although not to prior 2020 levels. Due to increasing demand and addition of debottlenecking capacity for residue conversion, IHS Markit estimates price spreads will moderate within a few years, but the timing of price recovery will be dependent upon a number of variables.
Refiners will produce more distillates (higher-value components derived from crude) as new demand arises for these products during the disrupted years, IHS Markit said. With HSFO priced at coal-thermal parity and demand for middle distillates (kerosene, jet fuel, diesel) increasing to blend to low-sulfur bunker fuel, refining margins will benefit, but in different ways.
“Refiners of sour-crude will be negatively impacted by the nearly valueless sour-crude residue, while refiners of sweet-crude conversion will experience moderately higher margins, but sweet-crude prices will reflect the low-sulfur residue value,” Barrow said. “It is the high-conversion refiners of sour crude that are expected to have extraordinary margins.”
Highly complex refineries will benefit the most from the IMO specification change, IHS Markit said. Highly complex refiners will produce the least amount of residual fuel oil and the highest amount of distillate and gasoline as compared to lower-complexity refiners.
Crude-price relationships, specifically between light-sweet and heavy-sour crude, will widen around the compliance timeframe, IHS Markit said. Assuming the specification change implements as announced on a global and instantaneous basis with no phase-in timing or quality transition allowances, the margin uplift will be acute in the compliance period from 2020 to 2021.
By: Peter Lyall, Eagle Lyon Pope and David Drew, Global Maritime
Despite oil prices remaining in the high US$40’s and a limited pickup in offshore activity worldwide, the Middle East is bucking the trend and seeing an increase in offshore activities around the oil and gas sector.
The Middle East was the only market globally to witness an increase in demand in offshore support vessel (OSV) activity in 2016 with a 2.6 per cent rise, according to industry analysts Petrodata. Furthermore, the region also seems to have been relatively unaffected by offshore drilling activity reductions with jack-up rigs remaining in high demand, according to the Global Jackup Rig Market Report 2016 by industry analysts, Research & Markets.
In addition, commercial shipping activities continue to be on the increase. Abu Dhabi’s Khalifa Port is just one example of a container port within the region that is set to expand, with plans to increase its annual container throughput to 2.5 million twenty foot equivalent units (TEUs).
Whether in the commercial shipping and ports sectors or the offshore oil and gas industry it is now as important as ever to have a consistent and comprehensive approach to marine risk.
As offshore oil and gas and commercial ports and shipping operations continue to grow within the Middle Eastern region, what is required for the successful alleviation of risk in these sectors? Specialist marine consultants, loss adjusters and engineers Eagle Lyon Pope (ELP) and its parent company Global Maritime Consultancy will attempt to address these issues in this article.
A Focus on Ports
Firstly, the focus must be on the ports and terminals themselves in order to ensure that all infrastructure is safe, functionally compliant, and conforms to industry guidance and best practices, whilst also being capable of adapting to future requirements.
Areas to consider in reducing risk in ports include effective port master planning; terminal feasibility studies for new developments; port marine safety audits; the provision of port designated persons; liability risk surveys; mooring and analysis; dredging; constructability support; and pilotage, navigation and ship manoeuvrability assessments.
Port and terminal operators are also required to have in place a contingency plan for marine pollution in order to support the decision making process, thus ensuring an adequate and timely response to such incidents. To this end, ELP can draft and deliver a pollution contingency plan bespoke to the port or terminal requirements.
We are also very conscious that the International Maritime Organisation (IMO)’s International Convention for the Control and Management of Ships’ Ballast Water and Sediments requires all international vessels to be equipped with a system to clean their ballast water before releasing it into the ocean. This prevents the transfer of alien marine species, such as bacteria and microbes.
This is another important pollution issue and it’s positive to see a global response to a global problem where incidents can be seen every day if not acted upon quickly. The IMO’s regulations will ensure standardisation in this area.
A Focus on Shipping
As vessel traffic increases and vessels become larger, safety in navigation and marine operations is of paramount importance. ELP employs an experienced team of master mariners, naval architects and marine engineers providing innovative solutions to highly technical marine issues. Using in-house operational simulation and risk management software disruption, delay, utilisation and risk can be effectively determined and managed.
Recently, ELP’s ports and shipping department conducted fast and realtime vessel simulations for berthing and unberthing Q-Flex LNG carriers at a newly developed floating storage regasification unit (FSRU) terminal within the Middle East.
The project included the facilitation of a full mission ship simulator workshop, which engaged stakeholders such as marine pilots from the region, ship’s masters, vessel operators, charterers and terminal operators.
Marine Casualty Investigation, Claims & Litigation
Marine accidents and incidents can potentially have catastrophic consequences, which inevitably result in insurance claims and potential litigation.
With this in mind, ELP’s team of marine master mariners, naval architects, marine engineers and insurance professionals can provide a global response service in investigating the cause, nature and extent of damage due to marine collisions, groundings, pollution and other incidents.
As vessels become more sophisticated, analysis of Automatic Identification System (AIS) and Voyage Event Recorder data is also becoming one of the key areas in which ELP can provide assistance to maritime lawyers and insurers.
ELP also provides loss adjusting services covering energy and marine claims, through to cargo claims, damage to ports, terminals, handling equipment, stevedore’s liability losses, personal injury and onshore work that includes power and utility losses, construction and business interruption.
ELP also carries out risk engineering for a variety of insurers and other clients in the Middle East and globally, providing underwriters with the information they need to assess the magnitude of specific risks.
Marine Warranty Services
Finally, Marine Warranty Surveys (MWS) are also an important means of managing risk for the insured and insurers. Global Maritime has more than 30 years of experience in Marine Warranty Surveying services covering transportation, construction, commissioning and decommissioning projects, assisting underwriters, brokers, oil companies, drilling contractors, offshore contractors and vessel owners.
In another Middle East example, Global Maritime provided MWS for a high-profile offshore concession, which included vessel suitability surveys, third party documentation reviews and the issuing of Certificates of Approval for marine operations and construction activities. As a leading provider of MWS, Global Maritime is constantly re-evaluating the process and procedures to ensure that the expectations of all are met.
Preparing for All Eventualities
As the Middle East offshore oil and gas and shipping markets continue to face risks, it’s vital that they are prepared for all eventualities. A consistent and process driven approach to risk, ports, shipping, marine casualties and loss adjusting is a good start.
Homayoun Falakshahi, senior research analyst for Middle East and North Africa Upstream at Wood Mackenzie speaks to Pipeline Magazine’s Nadia Saleem about Iran’s current oil and gas industry
What is the main incentive for Iran to bring in IOCs to develop its oil and gas resources?
Since the elections which resulted in President Rouhani’s win, solving the nuclear issue was the first mandate in clearing the way for reviving the oil and gas industry which has been suffering. The main incentive to bring international companies is to bring back investment rather than just knowledge. Meanwhile, some fields are hard to develop - like South Pars, so they needed to bring the technology that Iran doesn’t have.
How important are new oil and gas contract terms under Iran Petroleum Contract? The new contract terms are key to determine if Iran is able to bring back investors. Previous contract terms were known to be the world’s harshest - most of the time companies were unable to cover cost of investment under schemes which were more like service contracts.
What projects do you expect to go forward and what timelines do you see for this?
Iran has more than 50 upstream projects - these are only the discovered resources. Exploration hasn’t been a priority because the country has a lot of discovered resources, which go back nearly 50 years. So they have had other opportunities to grow. Additionally, Iran has between 14-18 exploration blocks which are on the do list for tendering. Although this been quoted to happen in two-three months, it’s more likely to be end of the year or even next year. Most of the interest from foreign companies will be on the developed resources - some of which are already producing.
What foreign investment does Iran need right now and what can attract these?
Iran has plans to develop 54 projects, which combined would need $114 billion in the next 20 years. Two-third of this is expected to come from foreign companies – that’s why it’s key for Iran to attract foreign investment. These are all new projects that didn’t exist 20 years ago. The main attraction Iran has is that most of these assets have a cost per barrel of around $15-16, which is low compared to others in the world (shale etc). Brazil is currently around $30-40, while North Sea’s operational cost alone is $20 per barrel. Iran can therefore afford to offer terms that are stricter - but they are being more pragmatic to ensure competition. In order to reach capacity targets, they need to do a lot of investment. We think this will happen over 10 years, not five. Most of the capacity building will be gas focused because of the high reserves (second highest after Russia) Iran has.
What challenges do you see in Iran being able to develop its oil and gas industry?
The first challenge will be international politics and policy of United States on the nuclear deal – so far we have yet to see something change. All the deals between certain dates can be cancelled if the snap-back clause in the sanctions deal is triggered. I would expect companies to play a cautious role although at this time this looks unlikely. Timeline is also a challenge. Iran is more optimistic that us on all the deals that will be signed. I don’t think Iran has the capacity to deal with all 50 projects at one time. It is likely that there will be series of tenders, and then every few months, some projects being awarded due to Iran’s international bureaucracy.
Iran has laid the groundwork to attract foreign oil companies and is fast signing contractors to speed up the development and revitalise the upstream and downstream sectors of its oil and gas industry. Thanks to a nuclear deal that lifted international sanctions against the Persian nation early 2016, Iran has been able to sign agreements with foreign companies that were not allowed to for nearly a decade. It has also boosted exports to markets and foreign funds it was barred access to.
Last month, National Iranian Oil Company and French group Total signed a draft agreement to develop phase 11 of South Pars field, the world’s largest gas field, marking the first Western oil major returning to Iran and signalling more of the same to come.
The country, with proven gas reserves at 34 trillion cubic meters, (the largest known source in the world) and one of the largest proven oil reserves estimated at 158 billion recoverable barrels, is currently in discussions with other oil companies such as U.K.’s BP, Russia’s Lukoil and Gazprom and Malaysia’s Petronas for developing its fields.
It has also signed preliminary deals with Eni and Shell for exploration and production. To satisfy domestic energy requirement and boost government revenues (as well as rebalance its books) through exports, Iran has set an oil production target of 6 million barrels per day (bpd) by 2021 from current 3.8 million bpd and gas production target of 365 billion cubic metres (cm) by 2021 from current 800 million cm.
The state energy firm identified 52 oil and gas projects (29 oil fields, 23 gas fields) for development to increase production capacity. Tehran hopes that 65-70 per cent of almost US $200 billion investment required to develop these fields will come from international companies.
While some of these projects are already developed but are in desperate need of infrastructure overhaul there are also sites of oil and gas finds which have yet to be developed. These two categories make up the bulk of projects being tendered.
Iran is meanwhile preparing to announce over the next three month its first round of oil and gas exploration tenders since the easing of economic sanctions but analysts expect this to be delayed with the NOIC occupied with the 50+ development projects. Iran has identified 18 explorations blocks so far.
There are three potential hurdles for Iran achieving its energy target in the given time frame; foreign funding contingent upon contract terms, boosting the country’s average daily rate of production and efficient use of gas.
Prior to sanctions, international companies operated in Iran through a buy-back scheme. These were short term contracts of 6-12 years in length, did not give any ownership interest to non-Iranian firms, and had fixed remuneration fee with disregard to changes in expenses or market oil price. With the aim to attract international firms and their funding, Iran set up a new model called Iran Petroleum Contract (IPC), which the cabinet approved in August last year but has yet finalise.
This is similar to a production sharing contract, where by it enables the foreign company to set up a joint venture with NIOC or its unit, was a duration of 20-30 years and with flexible remuneration and the rates of return are negotiable on a sliding scale and proportionate to risks surrounding development.
Firms including ENI, Total and Shell have all indicated their unwillingness to return to Iran unless the buy-back formula is altered. On the whole, contract terms will be a central criteria to attract the much needed foreign investment through IOCs, analysts say.
“The improvement of the new IPC compared with the unpopular ‘buy-back’ will do little to attract IOCs if they are not competitive with what is available globally. In order to reel in investments, it will fail to do so without assuring IOCs of the terms and without easing the negotiation process,” APICORP said in its energy research report on Iran.
Over the past five to six years, Iran’s average daily oil production volume has been around 3 million bpd, and export volumes have been around 1 million bpd.
More than 50 per cent of its 2016 production was from its four largest fields; Ahvaz, Gachsaran, Marun and Aghajari.
The aggressive production of the 1970s and the neglect in the 1980s have caused reservoir-pressure problems and water encroachment in a number of oil fields, according to a report by Arthur D Little (ADL) titled ‘A perspective on the Iranian upstream oil and gas industry’.
“It (is) a top priority for the country to develop a clear reservoir management strategy and introduce technologies that can quickly improve reservoir performance,” it said.
Iran’s average rate of recovery is currently at around 25 per cent, compared with a global average of 40 and best-in-class performers, such as the U.K., at 46.
Iran’s oil production and exports took a hit when the US and the European Union tightened economic sanctions against Tehran to curb its nuclear program. But Tehran surprised global markets by boosting production at faster a pace than most analysts had forecast after sanctions were lifted last year.
Following the deal that lifted sanctions, these volumes jumped to as high as 3.9 million bpd, through the second half of 2016.
“This increase was exclusively due to existing production capacity, opening wells that had been shut in, and exporting volumes that had been held in terminals and tankers. So with that in mind, and looking more closely at the target, achieving 6 million bpd by 2020 does appear ambitious,” ADL said in its report.
While Iran’s sustainable growth in production could lift it to 5 million bpd, a gap of 1 million bpd remains, the report said.
While Iran’s oil production and exports were hindered by political sanctions, its gas production has continued to rise consistently since the early 1980s at 10 per cent a year, driven by domestic demand and supported by government subsidies.
Iran has a gas production target of 385 billion cm per year by 2021, up from 2016 production volume of around 800 billion cm. Analysts expect this to be quite possible because major projects of South Pars and Kish are already in production.
The main concern is whether Iran will be able to meet export target. Only up to 10 per cent of 2016 gas production was exported, 80 per cent used for domestic needs, while the rest was flared, lost or re-injected.
“A possible way the export target and the growing domestic demand could both be met is through increasing production efficiency and reducing losses in the current system, as well as reducing flaring of associated gas volumes,” the Arthur D Little report said.
Meanwhile, the International Energy Agency said in its Gas 2017-2022 report that it expects Iran to account for the largest increase in Middle East production during the next five years, retaining its position as the biggest gas producer in the region even though its exports remain negligible due to a massive domestic consumption.
The region is expected to grow gas production by 1.8 per cent on average, up from around 580 billion cm in 2016 to 650 billion cm at the end of the outlook period of 2022.
Iran is expected to see an average growth of 2.9 per cent per year in gas production, leading to production of almost 225 billion cm by 2022, an increase of 36 billion cm.
Iran has in total an estimate of 4.5 trillion cubic metres of undeveloped gas discoveries, including the undeveloped phases of South Pars, the North Pars and a number of other fields, IEA said.
Volumes of gas for reinjection are expected to rise in the future, the report said, as Iran prioritises increasing oil production in order to maximise revenues as it recovers from the restrictive sanctions and to prevent further declines from its older oilfields.
While exact volumes of reinjected gas are not available, Iran is estimated to have injected 28 billion cm annually for the purpose of secondary oil recovery since 2010.
The GCC countries are in a diversification drive away from crude oil export dependency, but as global capacity also rises, increasing competition means a more uncertain long-term outlook for the region’s refineries, APICORP said in its new energy research report.
The refining sector saw tremendous growth over the past few years, mainly driven by significant government investment during a period of high oil prices, according to the report titled “An uncertain outlook for the refining sector in the GCC.” This was partly motivated by rising domestic demand in the GCC for gasoline, diesel and fuel oil in the transportation and power sectors. It was also driven by a diversification strategy as well as a commitment to create more value in regional economies. The last few years saw the expansion of refining capacity due to the commissioning of several projects. The completion of the two Saudi refineries - Yasref and Satorp - in 2014 and the expansion of the Ruwais facility in the UAE added approximately 1.2 million bpd of new and cleaner refining capacity. Built with an eye on supplying the growing Asian market, these new refineries have contributed to turning the GCC into a net exporter of refined products in 2016, particularly in the diesel segment.
The year 2016 marked a milestone for the GCC region as it became a net exporter of all refined products, although a marginal exporter of gasoline. On the other hand, diesel exports are expected to lead the way, having reached over 500,000 bpd in 2016, up from 310,000 bpd in 2015. Of the recent 1.2m bpd of additional capacity, diesel represents over half, while gasoline and jet fuel output stood at around 350,000 bpd and 140,000 bpd. These additions have had a measurable impact on trade flows, particularly in the diesel market. “The GCC’s new refineries are very sophisticated and are competing with the Asian ones. Additionally, the region’s strategic position (between Asia & Europe) give it a competitive edge,” Ghassan Alakwaa, research analyst at APICORP said to Pipeline Magazine. As GCC countries ramped up to reach full capacity in 2015, the economies slowed mainly from an oil-price slump, and governments introduced limited pricing reforms, slowing domestic demand growth and, in some cases, reversing growth. This was particularly the case for diesel in Saudi Arabia. After having peaked at 779,000 bpd in 2015, diesel demand declined to 701,000 bpd in 2016, representing a decline of 10 per cent in one year, the report said. The slowdown in the rate at which demand had been growing in the region is freeing up more refined products for export, competing with Asian refineries in a more congested products market.
As a result, Saudi Arabia has become a net exporter of diesel, with cargos competing in the European market. Further price reform will likely have a more significant impact on domestic demand, possibly freeing up more refined products for exports, APICORP said.
In 2016, the Kingdom exported 5,000 bpd of gasoline, coming from an average net import level of
55,000 bpd and 60,000 bpd in 2015 and 2014. “The impact of this is mostly felt in the Asia Pacific region and in India, which used to be major exporters of refined products – and particularly diesel - to the Middle East and Europe,” the report said. Prior to the recent ramp ups, Kuwait and
Bahrain had been the only two net diesel exporters in the region. While for gasoline, refineries in GCC countries were built to meet domestic demand.
“GCC diesel-oriented refineries were built with anticipation of growing demand in Asia. But diesel demand in China in particular has been flat-lining. As a response, these refineries are increasingly targeting the European market,” Alakwaa said. Meanwhile, China’s economic rebalancing away from manufacturing towards consumer goods and services has changed demand patterns within the country: diesel demand, related to heavy industry and transport of goods, is flat lining, while gasoline demand related to personal transportation continues to grow.
This has turned China into a net exporter of diesel, intensifying competition to a crowded refined fuel market.
Despite the oil price collapse since mid-2014, the region is still seeing significant investments in its refining sector and in the medium term, GCC countries are expected to add 1.5 million bpd of refining capacity between 2017 and 2021, APIRCORP said. The new capacity will be dominated by the two major additions in Saudi Arabia and Kuwait, as well as clean fuel projects in the region, providing GCC refineries with a competitive edge in a tough market.
Saudi exports in particular have a competitive edge in ultra-low sulphur diesel which meets European standards for cleaner fuels, while also offering less transportation cost and travel time than their Asian counterparts.
The 600,000 bpd Al Zour refinery in Kuwait and the 400,000 bpd Jazan project in Saudi Arabia will be the major additions. The Jazan refinery is expected to commence operation in 2018-19 while the Al Zour refinery is expected towards the end of the decade. The rest of the additions will come from the Duqm refinery and the Sohar expansion in Oman.
The 230,000 bpd Duqm refinery – a joint venture between Oman Oil Company and Abu Dhabi’s International Petroleum Investment Company (now merged with Mubadala) - is likely to come online in 2020, APICORP said.
In addition, Bahrain’s plans to expand the Sitra Refinery, which aim to add 100,000 bpd to the existing 260,000 bpd, are ongoing.
Most clean fuel projects are taking place in Saudi Arabia and Kuwait. The Jazan refinery will produce high quality transportation fuels including ultra-low sulphur diesel as the Kingdom aims to reduce sulphur content to 10 parts per million (ppm) and benzene amount to 1 per cent in gasoline. The recent refinery additions in the Kingdom represented a major shift in fuel grades. Prior to 2012, the
Kingdom’s sulphur level in diesel exceeded 500 ppm. Other refineries such as Ras Tanura and Riyadh are also being upgraded to meet higher standards. In Kuwait, ambitious plans are underway to upgrade and expand its refining sector with investments expected to surpass $20 billion in the medium term. The Al Zour refinery is expected to be one of the largest in the world, with high specifications allowing it to produce clean fuels. Projects to upgrade Mina Abdullah and Al-Ahmadi refineries will significantly reduce sulphur and benzene content – from 500
ppm to under 10 ppm in gasoline and from 4.5 ppm to 1 ppm in fuel oil.
The recently commissioned projects, as well as the ones expected online in the next five years, are in the process of turning the region into a leading hub for exports of refined products.
However, the outlook beyond 2021 is less certain. The Al- Zour project in Kuwait as well as the Sitra expansion program faced financing challenges which caused delay for several years, before finally reaching financial closure. On the other hand, tough competition in the products market and weakening demand is putting further pressure on the refining industry.
With US exports of distillates surging to record levels, Russia upgrading its refineries to produce more distillates, and Indian refineries ramping up their production, the competition in the products market, particularly in the diesel segment, has become more intense.
However, GCC export-oriented refineries might stand to benefit from the recent International Maritime Organisation rules which would alter demand patterns as fuel oil is replaced by diesel in 2020.
Wood Mackenzie forecasts that Bangladesh will see LNG demand rise to over 8 mmtpa by early next decade.
The government currently estimates LNG demand at over 700 mmcfd (around 5 million tonnes). However, due to the lack of domestic gas production, the government has stopped building gas pipelines and has been promoting the use of LPG in residential and commercial areas over the past few years.
On the other hand, while gas prices to all sectors have already increased twice in 2017 and averaging at around US$3/mmbtu, it still falls short of international LNG prices, making it attractive for both retail and commercial users. Currently, there is also no firm plan on gas price rationalisation.
These factors make the LNG import situation for Bangladesh more pressing.
PetroBangla is in talks with various parties for both long term and more flexible options for spot LNG deliveries. In June, it signed an MOU with AOT to supply up to 1.75 million tonnes of LNG. However, the deal is still under discussion and will be a part of its spot procurement strategy.
Conversations with key stakeholders indicate the Moheskhali FSRU, which will support its first LNG imports, remains on schedule to begin by the end of 2018. The onshore gas pipeline connecting the FSRU from Cox's Bazar to the main demand centre in Chittagong has also been completed.
Plans are also under way to build a subsea pipeline from Moheskhali Island to the mainland gas valve. A US$180 million financing package with Excelerate for the Moheskhali FSRU has also been concluded.
With plans for another 17 mmtpa of planned regas capacity via FSRUs and an onshore LNG terminal, the government is clearly in support to boost its LNG supply. Already, private capital is being attracted to this sector with the involvement of Summit Power, Reliance Power and Petronet who are looking to invest in these terminals.
Wood Mackenzie expects more upside to Bangladesh's LNG demand particularly if the 1.5 mmtpa Indian piped gas import gets delayed or cancelled, and if its coal-fired power plants do not come online as planned.
By: Håvard Devold, group vice president and chief digital officer for ABB’s oil, gas & chemical industries business unit
Oil and gas is in a critical state of transition. Following a sustained price boom, where production was prioritised at nearly any cost, 2014’s crash heralded a ‘new normal’. Experts now predict companies will need to operate within a US$40-$60 per barrel range for the foreseeable future. It has also become clear that traditional responses such as layoffs and plant shutdowns are insufficient. For example, as reported by Strategy&, part of the PwC network, while revenues of upstream, midstream and oilfield services companies declined 40 per cent between the third quarters of 2014 and 2015, operating expenses, only fell nine per cent. New approaches are needed, particularly given the industry’s aging asset base and retiring workforce.
Digitalisation now offers better solutions to old problems
Today’s affordable sensors, high capacity wireless networking capabilities and enhanced computer processing power mean remote management, automation and cloud-based computing enable companies to deploy fewer experts across a wider set of assets. For example, Queensland Gas Company (QGC) is able to manage a 540 km pipeline and over 6000 wells spread over 3500 km2 with fewer than four people. ABB’s System 800xA lets operators in a 24-hour control room in Chinchilla easily monitor and regulate the operations of wells, pipeline and processing facilities via a single user interface while liaising seamlessly with QGC’s Brisbane headquarters.
We’ve been using digital for years in pipeline oil and gas – so what?
While many midstream operators already use digital solutions in the form of advanced measurement devices such as electric flow metering and data-intensive pipeline inspection gauges, there is still considerable room to optimise operations.
To remain competitive in a low price environment, companies need to better distil the data they currently receive to generate new insights. They should also explore methods of collecting additional information, such as through the deployment of drones to conduct pipeline flyovers, regulations permitting. Fleet management can also be improved via increasingly sophisticated tracking technology. Additionally, with the growth in unconventional energy like liquid petroleum gas (LPG) and natural gas, companies must adapt aging infrastructure to track and optimise greater flows of an increasingly complex array of product from and to many new locations. To that end sensor and machine data, weather information and geolocation data can be more effectively mined to improve predictability and performance. Properly harnessed pipeline data can be used to optimise routes to market and help operators react quicker to fluctuating pricing and volumes. Electricity market indicators, for example, may signal increased future gas demand. Extracting such insights from big data will enable digitally savvy companies outperform competitors missing such signals by using outdated forecasting methods.
Similarly, from a supply standpoint, by analysing flow history and having a real-time view of conditions, operators can better predict where and at what pressure and volume product will arrive, meaning they can optimise configuration plans and maximise profitability. Digitalisation can also help maintain supply integrity. Theft from pipelines and other sources is estimated to cost over $37 billion globally. And, given a tanker can be filled in less than 15 minutes, prompt illegal tap detection through real-time monitoring is a useful tool to protect revenues.
Additionally, as outlined in figure 1, pipelines fail for various reasons. Many of these can be minimised through increased automation and surveillance, reducing operating expenses while also lessening the likelihood of major spills leading to even costlier regulatory burdens. Similarly, intruders will also be detected using laser pulses and all stations, manned and unmanned, will be surrounded by fences.
Each fence line and surrounding area will be automatically monitored 24 hours a day via fibre optic cables. The system will attempt to verify any questionable activity using CCTV and, if it ‘sees’ something suspicious, will sound the alarm and present the evidence to the operator along with what standard operating procedures should be considered.
Digitalisation can help midstream operators not only survive, but thrive in the ‘new normal’ of low prices. It can improve profit margins through better pipeline monitoring, more efficient transportation fuel cost management, more accurate supply and demand forecasting and by providing a better view of overall operations.
Global gas demand is expected to grow by 1.6 per cent a year for the next five years, with consumption reaching almost 4,000 billion cubic meters (bcm) by 2022, International Energy Agency said in its latest report GAS 2017.
China will account for 40 per cent of this growth, which will rise from the current consumption level of 3,630 bcm in 2016.
Demand from the industrial sector will be the main engine of gas consumption growth, replacing power generation, where gas is being squeezed by growing renewables and competition from coal.
The global natural gas market is undergoing a major transformation driven by new supplies coming from the United States to meet growing demand in developing economies and as industry surpasses the power sector as the largest source of gas demand growth, according to the IEA's latest market analysis and five-year forecast on natural gas.
This evolution of the role of natural gas in the global energy mix has far-reaching consequences on energy trade, air quality and carbon emissions, as well as the security of global energy supplies.
The United States - the world's largest gas consumer and producer - will account for 40 per cent of the world's extra gas production to 2022 thanks to the remarkable growth in its domestic shale industry. By 2022, US production will be 890 bcm, or more than a fifth of global gas output. Production from the Marcellus, one of the world's largest fields, will increase by 45 per cent between 2016 and 2022, even at current low price levels, as producers increase efficiency and produce more gas with fewer rigs.
While US domestic demand for gas is growing, thanks to higher consumption from the industrial sector, more than half of the production increase will be used for liquefied natural gas (LNG) for export. By 2022, the IEA estimates that the United States will be on course to challenge Australia and Qatar for global leadership among LNG exporters.
"The US shale revolution shows no sign of running out of steam and its effects are now amplified by a second revolution of rising LNG supplies," said Dr Fatih Birol, the IEA's executive director. "Also, the rising number of LNG consuming countries, from 15 in 2005 to 39 this year, shows that LNG attracts many new customers, especially in the emerging world. However, whether these countries remain long-term consumers or opportunistic buyers will depend on price competition."
Dr Birol added, "The environmental advantages of natural gas, particularly when replacing coal, also deserve more attention from policy makers."
US LNG will be a catalyst for change in the international gas market, diversifying supply, challenging traditional business models and suppliers, and transforming global gas security. A new wave of liquefaction capacity is coming online at a time when the LNG market is already well supplied. This LNG glut is already affecting price formation and traditional business models - and attracting new LNG-consuming countries like Pakistan, Thailand and Jordan.
At the same time, this ample availability of LNG is also creating new competition with pipeline gas supplies, which could benefit consumers. This intense competition is loosening pricing and contractual rigidities that have traditionally characterized long-distance gas trade. The change will be accelerated by the expansion of US exports, which are not tied to any particular destination and will play a major role in increasing the liquidity and flexibility of LNG trade.
Europe could see growing competition between LNG imports and pipeline gas as domestic production declines, creating extra uncertainty on the sources of future supply. The recent standoff involving Qatar, which supplies about a third of the world's LNG, and neighbouring countries has also underscored potential risks to gas supply security. "Even in a well-supplied market, recent events remind us that gas security remains a critical issue." said Dr Birol.
energy investment fell by 12 per cent in 2016, as increased spending on energy efficiency and electricity networks was more than offset by a continued drop in upstream oil and gas spending, according to the International Energy Agency's annual World Energy Investment report.
Global energy investment amounted to US$1.7 trillion in 2016, or 2.2 per cent of global GDP, while for the first time, spending on the electricity sector around the world exceeded the combined spending on oil, gas and coal supply, the report said.
The share of clean-energy spending reached 43 per cent of total supply investment, a record high.
China, the world's largest energy investor, saw a 25 per cent decline in coal-fired power investment last year and is increasingly driven by clean electricity generation and networks, as well as energy efficiency investment.
The United States saw a sharp decline in oil and gas investment, and accounted for 16 per cent of global spending. India was the fastest-growing major energy investment market, with spending up 7 per cent thanks to a strong government push to modernize and expand the power sector.
"Our analysis shows that smart investment decisions are more critical than ever for maintaining energy security and meeting environmental goals," said Dr Fatih Birol, the IEA's Executive Director. "As the oil and gas industry refocuses on shorter-cycle projects, the need for policymakers to keep an eye on the long-term adequacy of supply is more important. Even with ambitious climate-mitigation goals, current investment activity in oil and gas will have to rise from its current slump."
Dr Birol added: "The good news is that in spite of low energy prices, energy efficiency spending is rising thanks to strong government policies in key markets."
For the first time, the report tracks investment financing sources across the entire energy sector. More than 90 per cent of investments are financed from the balance sheets of companies, governments and households, reinforcing the importance of sustainable industry earnings in funding the energy sector.
After two years of unprecedented decline, global upstream oil and gas investment is expected to stabilise in 2017.
However, an upswing in US shale spending contrasts with stagnation in the rest of the world, signalling a two-speed oil market. At the same time, the oil and gas industry overall is transforming itself by delivering large cost savings and focusing more on technology development and efficient project execution.
Global electricity investment was nearly flat at $718 billion, with growing network spending mostly offset by fewer coal-power additions. Investment in renewable-based power capacity, the largest area of electricity spending, fell 3 per cent to $297 billion. While renewable investment is also 3 per cent lower compared with five years ago, it will generate 35 per cent more power thanks to cost declines and technology improvements in solar PV and wind.
Energy-efficiency investment rose 9 per cent to $231 billion with China, the fastest-growing region, accounting for 27 per cent of the total last year.
At this rate, China could overtake Europe, the largest spender on energy efficiency, within a few years, IEA said. More than half of the global investment in energy efficiency went to buildings, including efficient appliances, which account for a third of the world's total energy demand.
For the first time, the IEA tracked global energy sector research and development spending. It estimated that over $65 billion was spent on R&D worldwide in 2015, based on a bottom-up assessment of spending by public and private bodies.
Energy R&D is split about evenly between private money and public funding, but when it comes to low-carbon technologies the public sector takes a higher share. While the clean energy transition hinges on scaling up innovation, overall energy R&D expenditure has not risen in the past four years, nor has the clean energy component in particular. China has overtaken Japan as the world's top spender on energy R&D as a share of GDP.
The IEA report also found that while carbon emissions stagnated in 2016 for the third year, investment in clean electricity generation was not keeping pace with demand growth. Growth in new wind and solar PV generation growth is almost entirely offset by a slowdown in final investment decisions for new nuclear and hydropower expected in the coming years.
Consequently, investment in new low-carbon generation needs to accelerate just to keep pace with electricity demand growth. With well over 90 per cent of electricity sector investments funded with regulated pricing or contracts to manage revenue risks, government policies and new business models will play a preeminent role in attracting more financing.
Ian Thom, principal analyst, Middle East Upstream, Wood Mackenzie spoke to Pipeline Magazine’s Julian Walker about why Iraq’s oil production growth has under-performed but opportunities remain
Iraq has always had high ambitions and back in 2009 the country opened up its giant and super-giant fields to international investment. It attracted competitive bids from many of the world’s most capable operators. The country even claimed that its oil production target was 12 million bpd. Wood Mackenzie recently released a report on Iraq’s oil industry outlook.
Thom explained: “The report looks at the Basra area and the Masan area where the majority of Iraq’s giant fields are and where the greatest scope is for production growth. So if you look at Iraq and you take away the fiscal terms and the on-ground country risk characters you will be looking at resources that could reach 10 million bpd but it is only when you overlay the hard fiscal terms and country risk factors then you can see what isn’t being achieved.”
In its report, Wood Mackenzie said that Iraq’s southern technical service contracts (TSCs) have added 2.3 million bpd of oil production since 2009 – a remarkable achievement given the challenges. Of this, 700,000 bpd or 30 per cent is offsetting baseline decline while 1.6 million bpd or 70 per cent is growth. However, they are producing 4.7 million bpd below the current 8 million bpd plateau production target (PPT), and excluding baseline production, they have only achieved one-third of the incremental production required to meet the PPT.
“The South of Iraq is really a large resource base and it will drive the Iraq production story,” said Thom. According to the report, Rumaila has added the greatest amount of incremental production among the TSCs at 700,000 bpd. This is a brownfield development with renovation and upgrades of existing facilities, drilling of wells and crucially a large-scale water injection scheme.
BP has suggested the natural decline rate is 17 per cent, implying the TSC could be responsible for more than 1 million bpd of incremental production. West Qurna 2 has been a greenfield success adding 450,000 bpd of new production. West Qurna 1, Majnoon, Zubair and Halfaya have all added more than 200,000 bpd of production.
Meanwhile the smaller Missan Oil Fields, Gharraf and Badra TSCs have added a combined 250,000 bpd of production. On a relative measure, Rumaila and Halfaya are the most advanced at 50 per cent of the incremental production needed to meet the PPT. West Qurna 1, Majnoon and Missan Oil Fields are all below 25 per cent progress to the PPT. In many cases, the progress relative to the PPT is due to constraints outside the control of the contractor.
Constraints on Iraq’s oil growth
Wood Mackenzie highlighted a number of commercial, technical, political and security constraints on Iraq’s production growth. The decision to extend OPEC’s agreed production cut until March next year will certainly have an impact this year.
“This year the OPEC production agreement is going to be a main feature that will constrain Iraq’s oil production growth this year. We certainly expect monthly production to be roughly flat but I do not expect production to be cut from the southern IOC-operated fields.” In the November 2016 OPEC meeting, Iraq agreed to a production level of 4.35 million bpd for H1 2017.
This is a decrease of 210,000 bpd on its reference level. In the report, Wood Mackenzie explained that Iraqi oilfields will require large-scale water injection to achieve the expected recovery rates. The Rumaila field is currently injecting close to 1 million bpd of water sourced from the Shatt alArab river. This will support a 60 per cent recovery factor in the Main Pay (Zubair Formation).
Other fields have more limited access to water supply. For fields producing from the Mishrif Formation water supply is ever more critical. Mishrif oil is heavy and aquifer support is poor, resulting in rapid well decline rates. Long-term sustained production requires pressure support from water injection. “The other strains in the report are longer term in nature, such as mid-stream expansion or some of the water injection schemes. These are multi-year projects that require investments for a number of years to turn around and put the facilities in place and then to build the capacity up with drilling of wells,” he said. On the political front bureaucracy is seen as a major hurdle.
“Bureaucracy is certainly something that operators highlight as a main issue in operating in Iraq and it cuts across central government, Ministry of Oil, cabinet approvals for projects to the local entities. Across the board it is a challenge and the nature of the TSC contracts in Iraq is that you want to get a quick investment and then a quick ramp up of production. So anything that slows it down will be detrimental to the projects’ returns. For that reason it is a real challenge. It is a frustration for IOC’s in Iraq,” said Thom.
Iraq has a number of plans in place to increase the use of gas as more than 1 bcfd of gas is flared in the country. The Basrah Gas Company has been established to develop gas infrastructure. “The challenge is that the projects that Basrah Gas Company wants to implement will cost a lot of money and at the moment this is in short supply with Iraq having such a high reliance on oil revenue and that has fallen dramatically in the last couple of years. I expect that there will be a focus on the smaller, more incremental type projects that can be delivered in the current financial environment. There is clearly a lot of gas resource in Iraq but at the moment it is a lack of funds that is stopping final go-ahead. Some of the estimates we have seen for the more ambitious gas utilisation projects are particularly expensive and will be less likely to be progressed.The fundamentals are there for Iraq and clearly there to capture a great amount of its own gas resources. We expect it to continue but on a smaller scale while financial constraints remain.”
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The Gulf states, the world’s fastest growing demand center for natural gas, will need to create greater incentives to drive investment in new gas supply by removing all government subsidies that fix domestic gas prices at very low levels, a Gulf Intelligence research paper reported.
The Gulf holds more than 40 per cent of global gas reserves, much of it untapped, yet the volume of Liquefied Natural Gas (LNG) imports required by the region is quickly rising as domestic demand outpaces local pipeline supply. Regional collaboration in identifying cost-effective and easy-to-implement strategies to create both an integrated gas import ecosystem, while still maximizing the revenues of a growing export market, must become a greater priority for the Gulf’s industry leaders, the GI whitepaper found.
“Figuring out the most economic and efficient route to leveraging their gas reserves will unlock a much-needed treasure chest that will propel the Gulf’s export ambitions, while helping meet soaring domestic demand, especially amid intensifying competition from the US and Australia,” said Marc Howson, Senior Managing Editor of LNG at S&P Global Platts. “On the supply side of the industry, we have this game changing event, which is large scale U.S. LNG exports bringing in huge amount of flexible LNG supply in terms of the destination,” he said.
Middle Eastern LNG exporters face a tougher check list moving forward with global consumers developing a growing preference for short term contracts – long term contracts have historically been the bread and butter of LNG deals – means LNG sellers now need a large portfolio and sufficient flexibility to supply a growing number of countries.
Meanwhile, the International Energy Agency (IEA) expects gas demand in the Middle East to nearly double by 2040, while BP’s latest Energy Outlook forecasts that the global LNG market will grow seven times faster than pipeline gas trade and will account for half of the world’s traded gas up to 2035, compared to today’s 32%.
In the last three years alone, LNG imports into the region grew by more than 380% against a backdrop of relatively stagnant activity in other major energy demand hubs.
“The Middle East needs a comprehensive and robust infrastructure network to build a world-standard gas hub and meet demand across the region,” said Hatem Al-Mosa, CEO, Sharjah National Oil Company (SNOC). “Most gas importing countries require a range of LNG sources for their own energy security, both to plug a deficit and to provide a safety net when other gas supplies are hindered,” he said.
Gulf Intelligence, a Dubai-based strategic communications and research firm, launched a research report that tackled the critical question of how the Middle East could best transition from an LNG exporting region to now also fast becoming an import center. The whitepaper was harvested from a Workshop that took place recently in Abu Dhabi where 50 key stakeholders from the GCC’s energy sector gathered to explore viable solutions on how to both facilitate an LNG import ecosystem in the Middle East while maximizing the value of the region’s LNG exports.